Energy Transfer LP (NYSE:ET) Q2 2025 Earnings Call Transcript

Energy Transfer LP (NYSE:ET) Q2 2025 Earnings Call Transcript August 7, 2025

Operator: Good afternoon, and welcome to the Energy Transfer Second Quarter 2025 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Tom Long. Please go ahead.

Thomas E. Long: Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer Second Quarter 2025 Earnings Call. I’m also joined today by Mackie McCrea and other members of the senior management team who are here to help answer your questions after our prepared remarks. Hopefully, you saw the press release we issued earlier this afternoon. As a reminder, our earnings release contains a thorough MD&A that goes through the segment results in detail, and we encourage everyone to take a look at the release as well as the slides posted to our website to gain a full understanding of the quarter and our growth opportunities. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.

These statements are based upon our current beliefs as well as certain assumptions and information currently available to us and are discussed in more detail in our Form 10-Q for the quarter ended June 30, 2025, which we expect to file tomorrow, Thursday, August 7. I’ll also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You’ll find a reconciliation of our non-GAAP measures on our website. So let’s start today by going over our financial results. For the second quarter of 2025, we generated adjusted EBITDA of $3.9 billion compared to $3.8 billion for the second quarter of 2024. We saw several volume records during the quarter, including the midstream gathering, crude transportation, NGL transportation, NGL and refined products terminal and NGL export volumes.

We also saw strong volumes through our NGL fractionators, natural gas inter- and intrastate pipelines. DCF attributable to the partners of Energy Transfer, as adjusted, was approximately $2 billion. And for the first 6 months of 2025, we spent approximately $2 billion in organic growth capital, primarily in the NGL and refined products, midstream and intrastate segments, excluding SUN and USA Compression CapEx. Now turning to our results by segment for the second quarter. And let’s start with NGL and refined products. Adjusted EBITDA was $1 billion compared to $1.1 billion for the second quarter of 2024. We saw higher throughput across our Mariner East and Gulf Coast pipeline operations as well as through our fractionation facilities, which were offset by lower gains from the optimization of hedged NGL and refined product inventories as well as lower blending margins compared to the second quarter of 2024.

For midstream, adjusted EBITDA was $768 million compared to $693 million for the second quarter of 2024. The increase was primarily due to higher legacy volumes in the Permian Basin, which were up 10% as a result of processing plant upgrades and increased plant utilization as well as the addition of the WTG assets in July of 2024. These were partially offset by lower gathering volumes in the dry gas areas. For our crude oil segment, adjusted EBITDA was $732 million compared to $801 million for the second quarter of 2024. During the quarter, we saw growth across several of our crude pipeline systems as well as contributions related to the recently formed Permian joint venture with SUN. These were offset by lower transportation revenues, primarily on the Bakken pipeline.

In our interstate natural gas segment, adjusted EBITDA was $470 million compared to $392 million for the second quarter of 2024. This was primarily due to higher contracted volumes on several of our interstate pipeline systems. And for our intrastate natural gas segment, adjusted EBITDA was $284 million compared to $328 million in the second quarter of last year. During the quarter, we saw increased volumes across our Texas intrastate pipeline system due to third-party volume growth. This was offset by reduced pipeline optimization as a result of shifts to more long-term third-party contracts and their price spreads compared to the second quarter of last year. Now turning to our organic growth capital guidance. We continue to expect to spend approximately $5 billion on organic growth capital projects in 2025, even with the addition of the newly announced growth projects.

We expect to achieve mid-teen returns on a majority of our growth projects, with many also providing incremental downstream benefits. We expect the majority of the upcoming earnings growth to come from our Flexport, Permian processing, NGL transportation and Hugh Brinson Pipeline expansion projects, which are expected to ramp up in 2026 and 2027. And our newly announced projects, along with our significant backlog of opportunities, are expected to provide even greater visibility into additional volumes and earnings growth through the end of the decade. Taking a closer look at some of our recently approved and currently underway projects, we have some exciting updates on the natural gas side of our business, which are expected to support growing demand for gas-fired power plants, data centers and industrial and onshore manufacturing.

First, we were very excited this morning to announce the Desert Southwest pipeline project. This strategic expansion of our Transwestern pipeline will enhance system reliability and provide new and existing natural gas demand markets in Southern New Mexico, Arizona and across the Southwest region with access to low-cost, reliable Permian Basin volumes. This project includes construction of a new 516-mile 42-inch pipeline that will provide approximately 1.5 Bcf per day of transportation capacity from the heart of the Permian Basin to the Phoenix area in Arizona. We expect the project to cost approximately $5.3 billion, including $600 million of AFUDC, and expect the project to be in service no later than the fourth quarter of 2029. The project is backed by significant long-term commitments with investment-grade counterparties, and we expect to launch an open season later this quarter.

Also, we expect the capacity to be completely sold out upon completion of the open season. Depending on the final results of the open season, the project could be efficiently expanded to accommodate additional demand. Phase 1 of our Hugh Brinson Pipeline is expected to provide approximately 1.5 Bcf per day of natural gas takeaway from the Permian Basin upon being placed into service, which we expect to be no later than the fourth quarter of 2026. In addition, we recently reached a positive FID on Phase 2 of the pipeline project, which will include the addition of compression. This system will be bidirectional, with the ability to transport approximately 2.2 Bcf per day from west to east and approximately 1 Bcf per day from east to west. When this pipeline goes into service, we expect to have more than 2.2 Bcf per day contracted.

The Hugh Brinson Pipeline will provide significant optionality by connecting shippers to our vast intrastate natural gas pipeline network and other downstream pipelines, as well as access to the majority of the gas utilities in Texas and to every major trading hub in Texas. We believe this project further establishes Energy Transfer as the premier option for customers seeking a flexible and reliable natural gas solution to support their power plant and data center growth plans. And in July, we announced an open season on our Oasis pipeline, which offers an efficient option for shippers to sign up for future long-term natural gas transportation capacity out of the Permian Basin as it becomes available on the pipeline. This open season allows potential shippers the opportunity to ramp up their volumes over the next 4 years to better meet their projected volume growth curves.

We also recently approved the construction of a new storage cavern at our Bethel natural gas storage facility. This project is expected to double our working gas storage capacity at the facility to over 12 Bcf, and we hope to place the new cavern in service by late 2028. This expansion, which is expected to cost approximately $140 million, will increase our equity gas storage capabilities to serve growing demand in the heart of our extensive intrastate natural gas pipeline network. This will further strengthen the reliability of our systems as well as provide the opportunity to benefit from pricing volatility. We also recently approved an expansion on the SESH pipeline to serve growing power generation needs in the Southeastern region of the United States.

Looking at the Permian processing expansions. In the second quarter of 2025, Energy Transfer placed the 200 million cubic foot per day Lenorah II processing plant in the Midland Basin into service, and the plant is currently running at full capacity. We also recently placed the 200 million per day Badger processing plant into service, which utilized a previously idle plant that was relocated to the Delaware Basin. Volumes are ramping up nicely, and we expect to be at full capacity in the next few months. Over the last year, we have added approximately 800 million cubic feet per day of processing capacity, including 200 million cubic feet per day of optimizations that we completed at several of our other Permian processing facilities. As a result, our process volumes in the Permian Basin recently reached a new record of nearly 5 Bcf per day, and our Y-grade transportation throughput from the Permian also recently reached a new record.

In addition, we continue to expect our Mustang Draw plant to be in service in the second quarter of 2026. At our Nederland terminal, we recently placed our Flexport NGL Export Expansion Project into ethane and propane service. And we continue to expect to provide ethylene export services in the fourth quarter of this year. The project will ramp up throughout the remainder of 2025, adding up to 250,000 barrels per day of total NGL export capacity at our Nederland terminal. This project is fully contracted beginning in January 2026 with capacity initially split 50-50 between the ethane and ethylene and propane. We also recently approved the looping of an NGL pipeline upstream of our Lone Star Express Pipeline, which will expand our access to NGLs from the Northern Delaware Basin, where we see significant growth from our customers.

Looping this pipe is expected to allow us to source an incremental 150,000 barrels per day of NGLs for transportation on our NGL pipeline system from this high- growth region. The project will cost approximately $60 million and is expected to be in [ service ] in the first half of 2027. Now turning to Lake Charles LNG. We continue to make substantial progress towards commercialization of this project. During the second quarter, Lake Charles LNG signed an HOA with MidOcean Energy which provides a nonbinding framework for the joint development of the LNG project, with MidOcean entitled to receive 30% of the LNG production, approximately 5 million tonnes per annum. In addition, Lake Charles signed 20-year SPAs with Kyushu Electric Power Company and Chevron USA.

On the marketing side, we are in advanced discussions with multiple parties for our remaining capacity and are getting close to our target of 15 million metric tonnes per annum. Some of our potential offtake customers are also interested in equity in the project, which if concluded, would reduce our external financing requirements. As we have previously stated, we expect to sell equity in the project to reduce Energy Transfer’s ownership to approximately 25%. Over the last several months, we have been working with our financial advisers to finalize marketing materials as we prepare for the launch of the equity sell-down process. Now for a brief update around our new natural gas opportunities for new power plant and data center development. We continue to see a significant level of activity from demand pull customers to supply, store and transport natural gas for gas-fired power plants, data centers and industrial and onshore manufacturing.

And we remain in advanced discussions with several facilities in close proximity to our footprint. We would expect these types of projects to generate revenue relatively quickly. Our team continues to do an excellent job of identifying the most likely opportunities, and we will continue to provide updates as we move forward. Lastly, construction of 8 10-megawatt natural gas-fired electric generation facility continues. The second facility, which is serving our Badger processing plant, was recently commissioned, and we expect 2 more facilities to be placed into service by the end of the year, with the remainder expected to be in service in 2026. Now turning to our guidance. We now expect to be at or slightly below the lower end of our guidance range of $16.1 billion and $16.5 billion.

This is a result of weakness in the Bakken, slower recovery in the dry gas areas than we expected and a lack of normal volatility in our gas optimization business from spreads and storage margins. In addition, we expected stronger growth in our Permian crude business than we have seen year-to-date. In summary, given the substantial growth in demand for energy resources over the next several years driven by natural gas and natural gas liquids, we believe that Energy Transfer is the best positioned company in the industry to help meet this demand. We own one of the largest natural gas pipeline networks in the United States with physical assets in every major U.S. producing basin. We have more than 105,000 miles of natural gas pipelines that is coupled with significant gas storage, and we move approximately 30% of the U.S. natural gas production.

We are connected to nearly 200 gas-fired power plants in the country and have the ability to leverage strong relationships to develop new projects backed by higher quality counterparties on both the supply and demand side. We offer significant optionality, including bidirectional pipeline flow capabilities and strategically located storage assets, helping secure stable, uninterrupted supply. In addition, our operations team has extensive experience managing pipelines and a long-term proven track record of delivering reliable energy for our customers even during extreme weather events. Building on our natural gas thing, our Hugh Brinson and Desert Southwest pipeline projects and our Bethel storage expansion project further establish our natural gas pipeline business as the leading option for customers seeking dependable natural gas supply.

In addition to numerous opportunities in natural gas, we have one of the largest NGL businesses in the United States with more than 1.4 million barrels per day of NGL export capacity, and we are continuing to expand this business to meet the international demand. We also continue to evaluate projects to expand our crude oil pipeline network. Our backlog of well-contracted growth projects is expected to generate strong returns, enhance our integrated value chain and promote strong growth well into the future. We have a strong track record of organic growth, which has been enhanced by our long history of successful acquisitions. Each of these acquisitions have added strategic benefits and critical mass, providing the incremental opportunities for continued growth of our nationwide network.

This concludes our prepared remarks. Operator, please open the line up for our first question.

Q&A Session

Operator: [Operator Instructions] Our first question comes from Theresa Chen of Barclays.

Theresa Chen: On the gas to power front related to data centers, following up on your comments about being in advanced discussions with demand- pull customers, can you provide more detail on the commercialization efforts to date? What are the gating factors at this point? What is your updated view on the size and scale of the set of opportunities and when can we expect to see more discrete announcements on this front?

Marshall S. McCrea: Theresa, this is Mackie. Let me make — usually, I’ll make a statement at the end. I will make a quick statement and then I’ll answer your question, and it kind of rolls into that answer anyway. Since Kelcy started this over 25 years ago, our partnership, we started with a 10-inch pipeline that was idle, running through about 8 counties in East Texas, and we’ve grown to just a massive company through acquisitions and also through enormous organic projects throughout the U.S. And as I sit here today, we look at the folks that are running our business, both in office and especially out in the field, and we look at the adversity that we have unparalleled to any of our competitors by far, even with this challenged quarter that we had that we’re certainly going to talk about, I’ve never been — I’m sure everybody in here joins me, is excited about where we sit and where the future is for our industry, but even more importantly, for this call for our partnerships.

So we’re very excited about that, and a lot of that drive comes to your question. I’ve kind of been taking a ribbon for the last 3 months from these IR guys saying, don’t say 4 to 6 weeks on something. So I’m going to be a little careful there. But I will say this. These data centers have come out of nowhere. It’s a huge and enormously upside for companies like us that have big inch pipes all over the U.S. in very well-located areas for these types of projects, but they’re different. And they’re different in a couple of ways. One, these aren’t a plant that cost $1 billion or $0.5 billion. These are $50 billion, $60 billion, $100 billion-type facilities that we’re building to. So these things don’t just happen overnight. It takes time. And even the announcement on the Desert Southwest, it took 3.5 years to develop that.

So it has taken time. I, we are going to be more careful about what we say, but let’s say this. I can’t say this. Several months ago, we did sign our first kind of significant deal with a hyperscaler, a behind-the-meter hyperscaler here in Texas. It was 80,000 a day. We have recently, as of now, today increased that to 380,000 a day with the [indiscernible] to go to 475, maybe more upside from that from this one area in Texas. But it’s just one of — we’ve signed 3 deals now in Texas. We’re very close to 2 more. We’ve signed very close to signing one pretty significant one outside. But I’m not saying that’s 2, 3, 4, 5, 6 weeks, however long it takes. Every data center has different needs, different requirements, different supply sources, et cetera, et cetera.

So it does take a while to put these together. This one came together fairly quickly in light of how excited we are about it. We’re also excited about a lot of these others we’re chasing. So without making promises on new data center and/or a new power plant supporting data centers, any kind of predictions on weeks, just stay tuned. We’re pretty excited about what we anticipate announcing over these coming quarters.

Theresa Chen: And turning to the transmission side of things. Congratulations on the FID of Desert Southwest. Can you provide color on the expected build multiple for this project? And at this point, how much of the 1.5 Bcf per day is committed? And pending the results of the open season, to what extent can it be expanded?

Marshall S. McCrea: So gosh, we haven’t announced something in a while that is exciting as this. Beth Hickey and her team did an incredible job. This is just keeping your head to the grindstone for the last 2.5-plus years, very excited. We kept hearing about other projects, kind of ignored that, paid attention to what we do, and we’re very excited. Yes, we haven’t fully sold that out. We have zero concerns about selling out. In fact, to expand on a little bit, because of the incoming calls that we’ve had today, because of other conversations we’ve had over the last 3 or 4 weeks of folks that aren’t in heavy negotiation with us yet, not only do we have zero worries about fully selling out the 1.5, we also kicked off an evaluation today to increase that to a 48-inch, which would more than double the 1.5 Bcf.

Certainly not indicating that all on this call, but that’s what we’re going to do. But because of the enormous demand growth along this pipeline and in the Phoenix area, there’s just some upside that’s probably going to make sense, seriously looking at that. And if we do and get that going, we are confident that we’ll sell that out. So yes, from the standpoint of returns, there’s some upside that I kind of want to talk to about on this call, but it’s like everything else, this size, we’re going to be in that mid-teens kind of worst case on the returns on this project.

Operator: Our next question comes from Jeremy Tonet of JPMorgan.

Jeremy Bryan Tonet: I just wanted to pivot to Lake Charles, if I could. And maybe I missed it, but just wanted to see where we were with the EPC quote process and firming that up and I guess, marrying that against the SPAs and commercial agreements that you’ve established so far.

Marshall S. McCrea: Yes, this is Mackie again. And Tom is here for any follow-up [ adders ], he wants to add. And then [ Raj ] is here too, who is working closely, has been with EPC contracts for a while. We’ve had our own expectations as we’re waiting kind of for the numbers that have come in, and they’re dead on to what we expected. We certainly are including tariff which seemed to change daily, but any kind of tariff impact on that. So we’re very pleased of where the EPC contract looks like it’s going to come out. It’s right where we expect it to be, fits very well with what we’ve contracted and what we remain the contract. So we’re — as Tom said in the opening statements, we’ve been saying this for I don’t know how many years.

We’re very excited about this. We are pushing hard to get to the finish line, and we’re going to do everything we can to make that happen, but we still got some work to do, but there’s a lot of interest on this project, and we believe we’ll get there over the next couple of months. And then as we said, kick off the financing and get it to FID as soon as we can.

Jeremy Bryan Tonet: And then pivoting back to Desert Southwest, congratulations there. I was just wondering if you could share your thoughts, how ET views construction cost risk sharing as well as dealing with tribal land?

Marshall S. McCrea: Okay. This is Mackie again. As you can imagine, we’ve looked at that very closely over the last year, 1.5 years. If we have — we expect to have zero right of way across travel lands. And we don’t foresee of what we’ve seen so far any issues around right of way. We’re certainly going to be out in front of this, communicating, of course, with FERC, with the Department of Energy, Department of Interior, as well as we’ll be heavily involved in discussions with the governors of both New Mexico and Arizona as well as Texas. And we’ll be boots on the ground with our government relations team and those counties that we’ll be going through in all these 3 states. And so we’re — we’ve paid a lot of attention to that. We have put some contingency with some unknowns that we certainly don’t know about today. But we — I feel very good about where the costs are and very confident that we will meet or come in under the cost that we are estimating at this time.

Operator: Our next question comes from Keith Stanley of Wolfe Research.

Keith T. Stanley: And sorry to beat the dead horse on Desert Southwest. But I guess starting big picture, what do you see as what your competitive advantage was in winning this project over your peer, especially since it kind of goes along the route of their existing pipeline? Just how did you win this out and basically get all the utilities to support your project?

Marshall S. McCrea: Yes. Great question. I guess I go back to my opening statement. We just got some good people and we’ve got some good assets. And we did a great job of being patient, as I mentioned, and kind of rebuild a little bit. We’ve heard off and on that several other projects were about to go and all that stuff, and we just ignored that. We don’t worry about what other companies are doing. We worry about what we’re trying to get to the finish line. So with our team, their ability to negotiate and what we offer as far as supply sources. I mean, we’re tying to some big intrastate pipelines as sources. We’re tying to a lot of our large cryogenic facilities. So kind of tying all that together, we — as we’ve done over the years, we’re pretty good at using synergistic upside to projects that we get to the finish line on.

So a combination of all of that and just paying attention to the customers and responding to their needs and tough negotiations on all sides. We got a fair deal across the board, I think. I think our customer, very pleased with where we’re at, and just kudos to Beth and her team and all the work on our engineering behind all that and all the other support from a lot of the folks are in this office.

Keith T. Stanley: Great. And then I wanted to clarify the two earlier questions. So first, if you’re saying mid-teens returns on Desert Southwest, I mean, given it’s a 4.5 year kind of permitting and build period, is it fair to assume that’s, call it, a 6x EBITDA multiple or better? And then I wanted to follow up on Jeremy’s question. Is there any cost-sharing mechanism if you do run into hiccups on this project? Or is it a traditional structure where the midstream company is the one that’s in control of the costs and takes that risk?

Marshall S. McCrea: It’s a traditional deal. That’s just what we do. We know some of our competitors go out and do projects and low ball the rates, but say if the rates coming — cost coming higher, it will go up. So no, this is how we built this partnership. We do a lot of work, a lot of studying, and we’ve got a lot of good folks doing our right-of-way estimations and our pipeline and compression costs. And we feel — like I said earlier, we feel real good. We’ve got tariff costs in these. We’ve got contingency costs in these, we feel real good about it. And to your first half of your question, yes, 6x is a pretty good number to look at to consider.

Operator: Our next question comes from Jean Ann Salisbury of Bank of America.

Jean Ann Salisbury: I wanted to go back to the comment about 2025 fundamentals being a little bit weaker than you guys had forecast in the Bakken, Permian crude and gas growth. Is that kind of year-to-date comments or more just what you’re seeing in the back half?

Dylan A. Bramhall: Jean, this is Dylan. Good question. It’s a little bit of both. I think that we — through the beginning of the year, we’re just seeing a little bit lower volume. Some of that was coming out of the fourth quarter. Our plan had some growth in those we just haven’t seen materialize. To the extent that we plan, we are still seeing strong volumes in the majority of our areas, just not quite at the growth rate that we expected. And so looking at the back half of the year, they’re kind of a continuance. We see some growth coming, but we got a little bit of catch- up to get up to where we expected to be at this time of year. And so it’s like I said, you got a little bit on both parts of the year.

Marshall S. McCrea: Yes. And if you don’t mind, let me add to this. We couldn’t be more bullish about Bakken. Now that sounds odd because it certainly was kind of a black eye, it looks like for us in the second quarter, but there’s a lot of things happening on the scene. I’ll just touch on a few of them real quick. We had the TMX expansion project came on about a year ago. What that’s done is we’ve taken crude oil to refineries and more importantly now to export to Asia. It pulled a lot of the Canadian barrels out. That opened up some capacity on some pipelines out of Canada that now could be filled into a certain degree. With one of our competitors taking Bakken out, that’s going to go away in the next 1.5 years to 2 years.

That window is going to close and the volume growth in Canada is going to fill that up, and so those volumes are coming back. Secondly, what happened quarter-to-quarter was we saw volumes come off. We had some cold weather up there in April and May, that slowed down completions. There were some deferments of completions. There were even some curtailments, and we saw about 50,000 barrels a day less volume for the second quarter. In addition to that, there are also fires that had impact on barrels moving through both TMX projects, the original and the expansion. And so what that caused was a lot of refineries both in Canada and in the Northwestern U.S. really paid up to get oil to their refineries because they were short out of Canada. And so it increased our business through our rail terminals but took some volumes off of our pipeline that’s coming back.

So you kind of add all that up, there’s 80,000, 90,000 100,000, 120,000 barrels that have been kind of going in different directions or weren’t being produced that are going to come back in the system. And in addition to that — and there’s no questions about this yet, but I’m going to ahead and talk about it because I’m excited — we’re excited about it. [indiscernible] this whole team is that we’ve got this open season going with Enbridge and what Energy Transfer has done a good job on all these years is we look at our assets, we look at they’re being utilized. As everybody knows, we converted a natural gas pipeline interstate into a crude line that now helps move Bakken to the Gulf Coast. We converted an interstate pipeline out in West Texas and Mexico to an NGL.

We converted another pipeline to diesel, and that’s kind of what we do. But we also look at how do we keep our pipelines full today, and more importantly, for the next 10 or 15 years. And what’s going on in Canada is exciting to us. There’s a lot more egress needs to get out. And what better way than to help Canadian producers get production out to a pipeline that already exists. No risk on building, no risk on any kind of other issues. And so we’re excited about that. We think it’s a great opportunity to help Canadian producers. But more importantly, we’re going to do everything we can to make sure the producers in North Dakota have an outlet on our pipeline. But in addition to that, we have the ability to increase by adding pumps, capacity or pipeline.

And so it fits very well in working with Enbridge to help get more production out of the Canadian. So once again, I’ll start — I’ll end where I started. We’re very excited about the future of the Dakota Access.

Jean Ann Salisbury: That’s great. As a follow-up, as you know, there’s a lot of NGL pipeline capacity coming on in the Permian this year and next. Can you kind of dimension, I guess, how much volume loss you think you could see on Lone Star and whether the North Delaware looping project you announced today would offset most of that, maybe all?

Marshall S. McCrea: Yes. Our ninth frac’s coming on the end of next year so that kind of plays a role in all of this. We’ve got to have a home for it. But yes, we’re right on target. As Tom mentioned in the opening statements, we’re bringing these cryo up to Lenorah II. We’ve got Badger up and ramping up quickly. We’ll have Mustang Draw up first quarter, I think, of next year. We’re doing everything we can to get the barrels out of Delaware. That’s the $60 million expansion to get more down further stream. We’ve got more capacity on our existing Lone Star, as you just mentioned. And we feel real good about new contracts that we’re signing, of course, the ones that are related to our own cryos. New contracts with other third-party processing plants and then deals that were — that are coming up for termination.

We’re being very aggressive of rolling those over. So we’re focused and we’ve got a whole team working on this. Like I said, on Dakota Access, to keep these pipelines full, to build them to the capacity we need them, and then through time, to fill them up and then as time goes on, make decisions on further expansions. But we feel real good about where we’re at and kind of the timing when barrels start showing up with the completion of some of these projects that we have going on, including the Delaware expansion.

Operator: Our next question comes from Gabe Moreen of Mizuho.

Gabriel Philip Moreen: I just wanted to ask on — it seems like a long time ago at this point, the whole ethane export saga. But a, whether that had any impact at all on your quarterly results, but b, bigger picture, as you’re thinking about some of your expansions and other types of projects, whether it changes your plans in terms of markets you may be targeting either for ethane or ethylene exports and just how things would go in the future commercially for that.

Marshall S. McCrea: Yes. The first half of your question, no impact. Fortunately, it didn’t last long enough to have an impact. We weren’t concerned about it. The only impact, I’d say, I would say that it had was when you have deals with companies, international companies, all these years, they’ve relied on you do business with the U.S., the U.S. honors it. So that put a little bit of a black eye on us on our industry, on our country when we’ve got contracts and billions of dollars that were spent on crackers, in this case in China, with — in our case, with a very good partner with satellite. It was — it wasn’t fun, but we worked our way through it. Fortunately, that has gone away. We think it’s going to be probably a little bit more difficult to contract with Chinese crackers, good or bad.

We think that they’re probably going to be a little bit more hesitant. So to your question, yes, as we’ve always done, we’re looking at other countries, other companies in other countries, and we’re beating the bushes and there’s a lot of opportunities there. And we’re certainly very optimistic and believe that we will have further expansions. We’ll need further expansions both at Marcus Hook and at Nederland, and those will come, but this whole ethane issue that popped up here over the last several months certainly slowed things down with China.

Gabriel Philip Moreen: Thanks, Mackie. And maybe if I can ask just hydraulically in terms of what’s going on with the Hugh Brinson Pipeline in terms of the ability, I think, to make it bidirectional at this point. Are your customers just looking to wheel gas in terms of different points around? Or can you just maybe give us some more color in terms of what those hydraulics kind of do for the project and what sort of demand you’re looking to meet there with that?

Marshall S. McCrea: We’ve talked — we’ve been pretty excited about Desert Southwest, but it’s hard not to be as, if not, more excited about Hugh Brinson. Couldn’t have been better timing. We missed a lot of projects through the years, but we hit the rate of returns that we needed finally on this project when we got it to the end zone. It’s got tremendous interest. We have zero interest about selling it out, and we’re looking at maybe the next stage. But we also — by adding the bidirectional capability, we are able to offer other supply sources for our Texas markets. And so it’s really added a boost, especially a revenue boost potential for that project to make it a lot better rate of return than what we initially expected.

So as I mentioned earlier, we just — if you look at all our assets out of the country, it’s exciting, but gosh, especially in Texas. If you want to build a data center in Texas, who in the world would you want to do it better than Energy Transfer? When you look at all the 42-inch, 36-inch we have, all the storage support we have behind that and our ability and kind of path to being able to deliver at critical times. So we feel real good about that, and Hugh Brinson is going to be a great project for us for many years to come. And we’re very fortunate it kicked off when we did.

Operator: Our next question comes from Manav Gupta of UBS.

Manav Gupta: Congrats on all the good projects. I just wanted to quickly focus on Slide 8. It says 50% of your growth capital will be on nat gas focused projects for 2025. I’m trying to figure out, given all these new projects which are being announced, what would that number be for ’27, ’28? I’m not looking for an exact number, but should we assume that number trends upwards from here?

Dylan A. Bramhall: Yes. I think that’s safe to assume that number turns up. Obviously, we got a lot of time between now and then and a lot of projects that the team is working on a lot of great projects. Then we will look forward to bring a range of announcement here over the next couple of years. But right now, as we look at — yes, I think that number would trend quite a bit higher than what’s on the books right now, particularly with the Desert Southwest project.

Manav Gupta: Perfect. My quick follow-up here is a number of people are trying to develop this LNG, but you are somewhat unique because you have all these pipelines to feed your own LNG. So can you talk about the benefits of vertical integration of moving ahead with Lake Charles given all the infrastructure that you have in place to feed your LNG facility?

Marshall S. McCrea: Yes, this is Mackie again. Yes, as we’ve mentioned over the years, we’re very excited about LNG. But what really drives us on LNG is the pipeline transportation business that we’re so good at and that’s what kind of built our company. So as you mentioned, we’ve got multiple pipeline route into that area and into Lake Charles. We certainly will look at an expansion of a pipeline system to bring in more volumes once we get to FID. And we’re very excited about that aspect of the project. I mean LNG is going to be a great project. It’s going to be a good rate of return for us, but the real upside is our pipeline transportation business upstream of Lake Charles.

Operator: Our next question comes from Michael Blum of Wells Fargo.

Michael Jacob Blum: Wanted to go back to Lake Charles and really just clarify your goal to get to 15 million metric tonnes to get to FID. Does that need to be all firm contracts? Or will you proceed with the combination of HOAs and SPAs?

Marshall S. McCrea: And Tom may correct this or modify it, but what we plan on doing is once we have SPAs and/or HOAs initially — I’m sorry, HOA or SPAs, we will move forward on finance, kicking off financing once we have our target level of either one, a combination of both. So the HOAs are, for all practical purposes, end up being binding, even though they’re not. But we — with all the parties we’re dealing with, once we sign the SPA, we’re 99% positive, we’ll get to an HOA — once we sign the HOA, there’s more [indiscernible]. But once we sign the HOA, we’re confident that we’ll get to SPA in a fairly, relatively short period of time.

Michael Jacob Blum: Okay. Great. That helps. And then I just wanted to ask about how we should think now about the cadence of growth CapEx beyond this year now that you’ve got Desert Southwest, Lake Charles is moving towards FID, it seems? And you’ve also announced here another steady rate of additional projects, and it seems like there’s a lot more behind this. So just wanted to get a sense for the cadence beyond this year.

Thomas E. Long: Michael, listen, this is Tom, and I know that Dylan was walking through that a little bit, one of the previous questions. But that is fair. With all these good projects we’re having right now, we are seeing that grow. We’ll probably be ready later this year to be able to give a little more guidance around that. We normally wait until the year-end earnings call to provide the guidance for 2026. But with all the moving pieces here right now on a lot of very, very good projects that we’re excited about, just give us a little bit later. But you can appreciate though, those are going to be coming up. And that’s not just the Desert Southwest, the Hugh Brinson, the storage, all the projects we’re talking about right now. And if Lake Charles — when Lake Charles gets going, that one, likewise, we’ll be rolling that one in. So just give us a little more time with all the moving pieces, but you can see that definitely going up.

Operator: Our next question comes from Zack Van Everen of TPH.

Zackery Lee Van Everen: Maybe going back to the AI power projects. Great to hear the hyperscaler contract that you spoke to. It seems like a lot of these projects are on or around existing assets. And I know you probably can’t give an exact number, but is there a range of EBITDA contribution from these projects you could point to? If it’s within a mile of the facility, is it a lower contribution? Just trying to get an idea of what these projects might look like.

Marshall S. McCrea: Yes, this is Mackie. It’s probably a little early on to get to that kind of detail. And the reason being is, some of these we may have a mile or two away, some of them, we may have 25 miles away. For the most part, they’re much closer to our systems, but we will have an added fee for that. But I guess I would state that as we get more and more of these done, it will be a very impactful number from an EBITDA perspective and every single project will have — some will have much higher EBITDA impact than others. But I don’t think on this call, we can really quantify exactly what that is, but we are very bullish on where all the — where that business is going to take us.

Zackery Lee Van Everen: Sounds good. And maybe shifting back to the NGL looping project. Just curious if the 150 barrels is shifting off of another system or is this expected to be kind of incremental growth from producers in that area?

Marshall S. McCrea: It will be incremental growth. As Badger ramps up, we’re running out of capacity where we’ve got more growth up in the Southern Delaware and New Mexico. So it’s — we expect growth rolling over contracts that exist, new growth on our processing plants that are coming online as well as third-party processing plants that our NGL team is actively negotiating with.

Operator: Our final question comes from John Mackay of Goldman Sachs.

John Ross Mackay: I think Manav asked this one way, but I might ask it in another. Just looking more broadly, you’ve announced a ton of gas projects now, do you have a sense of what percentage of the overall business gas could look like as we look forward a couple of years?

Marshall S. McCrea: Yes, John, this is Mackie. When you say overall, you mean kind of like a Bcf?

John Ross Mackay: Sorry, I guess, percentage of total ET EBITDA.

Dylan A. Bramhall: I don’t think at this point, we’d give an exact number on that. Like you said, there’s a lot of projects in the works and a lot of good growth opportunities in all of our segments here. I’d say as you look right now and you look at the main segments there with the expansion of — the 2 biggest expansion projects with the Hugh Brinson in intrastate and Desert Southwest in the interstate, obviously, the expectation is for those segments to grow as a percentage of the whole, probably the quickest of any of our segments as we look out.

John Ross Mackay: And maybe taking that just a little further. I mean, with a lot of these — a couple of these projects being a little later dated, are you guys getting into a position where you might be able to talk about kind of a go-forward kind of EBITDA growth rate target from here or anything like that, maybe not necessarily guidance, but at least a framework or a general target?

Thomas E. Long: Yes, listen, this is Tom again. That’s not been something that we probably bounced around here a lot as far as the discussion. Clearly, with all this happening, we always have a very, very robust forecasting process around here. So we’re always in front of rating agencies with those, et cetera. We could consider that. But I think as we sit here right now, we’ve not necessarily discussed giving some type of a growth trajectory. Ours gets a little bit lumpy, especially when you blend it in with the M&A. So an acquisition comes along, you can probably appreciate the fact that sometimes that will all of a sudden make a jump. And then other times, we’re talking about the projects we are right now, which all have varying years of build that come with them. So anyway, Dylan, I don’t know if you want to add a little bit more to that?

Dylan A. Bramhall: I’d just point back to one thing that we’ve said publicly before, which is we have our stated growth target for distributions of 3% to 5%. And the additional color we’ve given around that is that 3% to 5% for us has to provide a baseline for where we believe is a floor to the long-term growth in distributable cash flow per unit. We’re not manufacturing — our plan is not to manufacture distribution growth by getting into coverage. So that number is meant to provide a floor for the long-term growth rate there at a bare minimum.

Operator: This concludes the question-and-answer session. I would like to turn the conference back over to Tom Long for any closing remarks.

Thomas E. Long: All right. Well, listen, we thank all of you for joining us, as always, and we look forward to the follow-up calls. I hope everyone has a good rest of your day.

Operator: This concludes today’s conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.